Hydraulic fracturing often requires the use of well treating materials capable of enhancing the production of fluids and natural gas from low permeability formations. In a typical hydraulic fracturing treatment, a fracturing treatment fluid containing a solid proppant is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. The fractures radiate outwardly from the wellbore, typically from a few meters to hundreds of meters, and extend the surface area from which oil or gas drains into the well. The proppant is deposited in the fracture, where it remains after the treatment is completed. After deposition, the proppant serves to prevent closure of the fracture and to form a conductive channel extending from the wellbore into the formation being treated. As such, the proppant enhances the ability of fluids or natural gas to migrate from the formation to the wellbore through the fracture.
Many different materials have been used as proppants including sand, glass beads, walnut hulls, and metal shot as well as resin-coated sands, intermediate strength ceramics, and sintered bauxite; each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. The apparent specific gravity (ASG) of these materials is indicative of relative strength; the ASG of sand being 2.65 and the ASG of sintered bauxite being 3.4. While increasing ASG provides greater strength, it also increases the degree of difficulty of proppant transport and reduces propped fracture volume. Fracture conductivity is therefore often reduced by the use of materials having high ASG. More recently, attention has been drawn to the use of ultra lightweight (ULW) materials as proppant materials. Such materials have an apparent specific gravity (ASG) less than or equal to 2.45.
It is generally desirable for the fracturing fluid to reach maximum viscosity as it enters the fracture. The viscosity of most fracturing fluids may be attributable to the presence of a viscosifying agent, such as a viscoelastic surfactant or a viscosifying polymer, in the fluid. Conventional viscosifying polymers include such water-soluble polysaccharides as galactomannans and cellulose derivatives. The presence of a crosslinking agent, such as one which contains borate (or generates borate), titanate, or zirconium ions, in the fracturing fluid can further increase the viscosity. The increased viscosity of the gelled fracturing fluid affects both fracture length and width, and serves to place the proppant within the produced fracture.
Recently, low viscosity fluids (such as water, salt brine and slickwater) which do not contain a viscoelastic surfactant or viscosifying polymer have been used in the stimulation of low permeability formations. Such formations are also known as tight formations (including tight gas shale reservoirs exhibiting complex natural fracture networks). To effectively access tight formations wells are often drilled horizontally and then subjected to one or more fracture treatments to stimulate production. Fractures propagated with low viscosity fluids exhibit smaller fracture widths than experienced with relatively higher viscosity fluids, resulting in development of greater created fracture area from which the hydrocarbons can flow into the high conductive fracture pathways. In low permeability reservoirs, fracture area is generally considered proportional to the effectiveness of the fracture stimulation. Therefore, low viscosity fluids are generally preferred for stimulation of tight gas shale reservoirs.
Slickwater fluids are basically fresh water or brine having sufficient friction reducing agent to minimize tubular friction pressures. Generally, such fluids have viscosities only slightly higher than unadulterated fresh water or brine; typically, the friction reduction agents present in slickwater do not increase the viscosity of the fracturing fluid by any more than 1 to 2 cP. Such fluids are much cheaper than conventional fracturing fluids which contain a viscosifying agent. In addition, their characteristic low viscosity facilitates reduced fracture height growth in the reservoir during stimulation. Further, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or viscoelastic surfactant in the fluid.
While the use of low viscosity fluids is desirable for use in the stimulation of low permeability formations, the pumping of proppant-laden slickwater fluids has proven to be costly since proppant consistently settles in the manifold lines before the fluid reaches the wellhead. This is particularly evident when the fracturing fluid contains a higher concentration of proppant and/or when the proppant employed has an ASG in excess of 2.45. Such materials are very likely to settle in the manifolds before the fluid ever reaches the wellhead. Since proppant settling is affected by the viscosity of the treatment fluid, a high pump velocity is required to prevent settling. However, under certain conditions rate alone is insufficient to prevent settling as settling is also dependent on proppant size and specific gravity. Further, since manifolds have different dimensions, mere modification of fluid pump rate in one area may not address the problem in another.
In addition to the settling of proppant in the manifold lines, there is a real danger of proppant settling inside the fluid end of the pump. Within the pump, pistons move under a sinusoidal wave pattern. As such, the pistons move slowly, then faster, then slow and then stop momentarily. The process repeats for each of the pistons. Settling of proppant in the housing of the pump may damage the pistons as the pistons attempt to move or crush the proppant. This is particularly a problem when proppants are composed of high compressive strength, such as ceramics.
Proppant settling from low viscosity treating fluids within the horizontal section of the wellbore is also of concern. Such settling can occur as a result of insufficient slurry flow velocity and/or insufficient viscosity to suspend the proppant. Excessive proppant settling within a horizontal wellbore can necessitate cessation of fracturing treatments prior to placement of the desired volumes. In order to mitigate settling issues, high pumping rates are typically employed to effectively suspend the proppant for transport within the horizontal wellbore section. However, high pumping rates can result in higher than desirable treating pressures and excessive fracture height growth.
Alternatives are desired therefore for proppant-laden fracturing fluids which provide the benefits of slickwater in tight gas reservoirs but which do not cause damage to pumping equipment or do not allow for proppant settling in horizontal wellbores.